a.k.a. An Introduction to my Day Job
The process by which plant material is converted to coal generates large quantites of methane gas, which is often trapped within the coal. The presence of this gas is very well known due to underground coal mining, where it presents a serious safety risk. This is coalbed methane, often refered to as CBM.
Coalbed methane differs from a typical sandstone natural gas reservoir in the following ways:
- Methane is stored within the matrix (the coal) by a process called adsorption. The methane is in a nearly liquid state, lining the inside of the coal pores.
- The porosity of the matrix typically refers to the size of the cleats (fractures running throughout the coal), not the porosity of the coal rock itself. Porosity is typically very low compared to a traditional reservoir (less than 3%).
- The gas is often, but not always, sealed in the coal by 100% water saturation of the cleats. The reservoir must be dewatered before the gas can begin to desorp from the coal.
Estimated CBM reserves vary, but are huge. A 1997 estimate from the U.S. Geological Survey predicts more than 700 trillion cubic feet of methane within the US, and at least 100 trillion cubic feet of it being economically viable to produce. At today’s natural gas prices ($6.05 USD / MMBtu), 700 TCF represents $4.37 trillion USD. (1031 Btu / scf)
High natural gas prices are making CBM economically viable where it previously may not have been. Coalbed methane wells produce at low gas rates (typically maxing out around 300 Mcf/d), and can have large inital costs.
The production profiles of CBM wells are typically characterized by a "negative decline" in the gas rate as water is pumped away and gas begins to desorp and flow. A dry CBM well does not look very different from a standard well, except that the gas rates are lower and decline at a much slower rate.
A typical ten-year CBM gas rate forecast, showing a negative decline for the first couple years of production.
The methane desorption process follows a curve (of gas content vs. reservoir pressure) called a Langmuir isotherm. The isotherm can be analytically described by a maximum gas content (at infinite pressure), and the pressure at which half that gas exists within the coal. These parameters (called the Langmuir volume and Langmuir pressure, respectively) are properties of the coal, and vary widely. A coal in Alabama and a coal in Colorado may have radically different Langmuir parameters, despite similar other coal properties.
A typical CBM isotherm, characteristic of a San Juan basin coal.
The increasing gas rates seen in a negative decline are caused by increasing relative permeability as the water saturation around the wellbore decreases. As there is less water in the coal cleats, the gas is able to flow more and more into the wellbore to be produced.
A set of relative permeability curves. As water saturation decreases, more gas and less water is produced from the coal.
As production occurs from a coal reservoir, the changes in pressure are believed to cause changes in the porosity and permeability of the coal. This is commonly known as matrix shrinkage/swelling. As the gas is desorbed, the pressure exerted by the gas inside the pores decreases, causing them to shrink in size and restricting gas flow through the coal. As the pores shrink, the overall matrix shrinks as well, which may eventually increase the space the gas can travel through (the cleats), increasing gas flow.
An example of CBM matrix shrinkage. Three matrix shrinkage correlations are shown: Palmer and Mansoori, Shi and Durucan, and Seidle.
Thank you for your interest in this article!
I was bored one day, and wrote this up as a Wikipedia entry for coalbed methane… excluding the self-indulgent advertising. In the future, I may write a bit about building a mathematical model of a CBM reservoir. It’s an interesting and surprisingly simple process.